Formation treating

ABSTRACT

Disclosed are processes for treating a subterranean formation to improve the permeability distribution by reducing the permeability in high permeability zones, so fluids injected for oil recovery purposes will sweep more uniformly through the formation. The processes involve injecting a polymerizable compound, preferably a monomer or oligomer of furfuryl alcohol, together with a diluent, preferably an ester such as butyl acetate, and a suitable acid catalyst for the formation conditions, generally toluenesulfonic acid. The fluid may be injected in a liquid phase or mixed with steam or non-condensable gas to form an aerosol, which is injected then into the formation prior to the injection of the oil recovery fluid, which may be water, surfactant fluid, polymer fluid, or steam.

REFERENCE TO COPENDING APPLICATION

This application is related to copending application Ser. No. 07/718,513filed Jun. 21, 1991 for "Sand Consolidation Methods" and to copendingapplication Ser. No. 07/762,150 filed Sep. 19, 1991 for "SandConsolidation Methods."

FIELD OF THE INVENTION

This invention pertains to a method of treating formations. Moreparticularly, this invention pertains to a method for treatingformations which exhibit variations in permeability from one depth toanother within the formation, which cause enhanced oil recovery fluidsinjected into the formation to enter the formations in an unevenfashion, with a substantial portion of the injected fluid entering arelatively small portion of the total formation due to the highpermeability of one portion of the formation. The treatment reduces thepermeability variation and causes more even invasion of the formation byenhanced oil recovery fluids. Still more particularly, this methodinvolves injecting a polymerizable compound into a formation having poorpermeability distribution, in order to reduce the permeability of themore permeable zones in the formation, so a subsequently injected oilrecovery fluid will enter the formation uniformly.

BACKGROUND OF THE INVENTION

When a deposit of petroleum is located in a subterranean formation, oneor more wells are drilled into the formation and the petroleum isallowed to flow or is pumped to the surface of the earth during a periodof production commonly referred to as primary production. Unfortunately,primary production recovers only a small fraction of the petroleumoriginally present in the formation. It has become common practice toapply some form of treatment commonly referred to as enhanced oilrecovery to the formation to stimulate the production of petroleum, inorder to obtain a larger portion of the petroleum from the formation.The commonest form or treatment comprises injecting water into theformation, which displaces a portion of the petroleum through thepermeable formation to a remotely located well by means of which it isrecovered to the surface of the earth. Various chemicals includingviscosity increasing polymers and surface tension reducing surfactantshave been incorporated in the injection water, in order to increase thetotal amount of petroleum recovered from a formation. Injection of steaminto subterranean formations containing viscous petroleum has beenparticularly successful, since primary production recovers very littleand in some cases, none of the viscous petroleum originally present inthe formation, and steam stimulation has resulted in significantproduction at relatively modest cost. Steam stimulation may involveinjecting steam into one or more wells on a continuous basis andrecovering oil from remotely located wells, or it may involve injectingsteam into a well for a period of time followed by producing petroleumfrom the same well.

When a well is drilled into a subterranean petroleum formation, it iscommon practice to establish communication between the interior of thewell and the formation over a substantial portion of the verticalthickness of the petroleum formation. When fluids are injected into theformation via these perforations, it is desirable that the recoveryfluid enter the formation relatively evenly, e.g. half of the fluidenters the top half of the formation and half of the fluid enters thebottom half of the formation. Unfortunately, distributions inpermeability in formations are so uneven that it is frequently observedthat a substantial portion of the steam is entering only a very smallportion of the total thickness of the petroleum formation. Oil fieldservice companies offer well surveys which can measure and determine theinjectivity profile of an interval, which indicates how evenly the fluidis entering the formation. If the injectivity profile is unfavorable,meaning a major portion of the recovery fluid is entering only a smallportion of the thickness of the formation, then the effect of fluidinjection on the well will be greatly reduced and some type of remedialtreatment must be applied if a significant portion of the oil present inthe formation is to be produced by the enhanced oil recovery process.

This problem has been long recognized by persons working in thisparticular area, and many prior art methods describe processes to beapplied to wells for the purpose of altering the fluid injectivityprofile of an interval penetrated by a well to a more favorable profile,e.g., to reduce the permeability of the more permeable intervalssubstantially without reducing the permeability of the less permeableintervals to a similar extent. A great many prior art referencesdescribe formation treating processes employing polymers such ascarboxymethylcellulose which is injected into the formation, andcross-linking of the polymer within the formation is caused by thepresence of trivalent ions such as chromium which, depending on theparticular application, are injected previously or subsequently to thepolymeric fluid. Many of these processes require successive injectionsof fluids in order to accomplish sufficient cross-linking of thepolymers to accomplish significant reduction of permeability in the veryhigh permeability zones, sometimes referred to as thief zones, informations, in order to improve the injectivity profile of asubsequently applied oil recovery process involving injection of fluidinto the formation for the purpose of stimulating oil production.

Other prior art methods involve injecting polymers into the formationwhich can be caused to thicken after they have entered the formation.

While many of these procedures have enjoyed success in certainsituations, many formations have not responded favorably to prior artmethods for a variety of reasons. Many treatment processes requireinjection of a plurality of different slugs into the formations tointeract, and this greatly increases the time and cost of the treatmentprocedure. Many of the compounds utilized are quite expensive, and thisalso adds significantly to the cost of the permeability alteringprocesses.

When the oil recovery method to be applied to a formation involvesinjection of steam, yet another weakness of prior art methods isencountered. Many of the polymers employed in prior art methods are notstable at the high temperatures encountered during the injection ofsteam into the formation, which may run from 220° to 700° F., andtherefore these procedures cannot be employed when steam is to beinjected into the formation.

In view of the foregoing brief discussion, it can be appreciated thatthere is an unfulfilled need for a relatively inexpensive process thatcan be applied to formation to reduce the wide variations inpermeability of the formation. There is a particularly seriousunfulfilled need for a process to be applied to a subterranean formationwhich will resist the temperatures of subsequently injected hightemperature fluids such as steam.

PRIOR ART

Numerous prior art references utilize materials similar to that used inour process for a different purpose, that of controlling unconsolidatedsand flow in producing wells. These references are detailed below.

In U.S. Pat. No. 4,427,069 there is disclosed a procedure forconsolidating sand in a formation adjacent to a wellbore using anoligomer of furfuryl alcohol, in which the catalyst used is a watersoluble acidic salt, preferably zirconyl chloride, which is injected inan aqueous solution into the formation prior to the resin containingfluid injection.

In U.S. Pat. No. 4,842,072 for "SAND CONSOLIDATION" we disclosed aparticularly effective method for consolidating sand utilizing a mixtureof a polymerizable resin such as an oligomer of furfuryl alcohol and adiluent such as butyl acetate and an oil soluble, slightly water solubleacid catalyst such as orthonitrobenzoic acid is injected followed byinjection of salt water to reestablish permeability.

In U.S. Pat. No. 4,669,543 which issued Jun. 2, 1987, there is describeda method for consolidating sand using an acid curable resin andutilizing as a catalyst, the reaction product of an acid, and an alkylmetal or ammonia molybdate. In that instance, the catalyst isincorporated in an aqueous carrier fluid which comprises the continuousphase of an emulsion in which the polymerizable resin is the dispersedor discontinuous phase.

U.S. Pat. No. 5,010,953 which issued Apr. 30, 1991 teaches a sandconsolidating process using a polymerizable compound such as furfurylalcohol, a diluent such as a low molecular weight alcohol, an acidcatalyst and an ester and as an additive to reduce shrinkage, acopolymer of starch and a synthetic polymer such as acrylamide oracrylate.

U.S. Pat. No. 5,005,647 which issued Apr. 9, 1991, discloses a processfor shutting off permeable zones in wellbores to reduce excess waterflow using fluids similar to that described in U.S. Pat. No. 5,010,953discussed above.

U.S. Pat. No. 5,005,648 which issued Apr. 5, 1991 describes a method oftreating permeable zones in a formation to reduce water flow into a wellcompleted therein by injecting a fluid-containing polymerizablecompound, an ester, an alcohol diluent, an acid catalyst such asorthonitrobenzoic acid or toluenesulfonic acid.

U.S. Pat. No. 4,938,287 which issued Jul. 3, 1990 describes an oilrecovery process in which a preflush such as ethyl or butyl acetate isinjected into the sand to be consolidated to remove oily residue,followed by injecting the treating fluid containing the polymerizableresin, diluent, ester and acid catalyst to accomplish sandconsolidation.

U.S. Pat. No. 4,892,072 which issued Jun. 27, 1989 describes a sandconsolidation process using a single treating fluid comprising apolymerizable compound such as furfuryl alcohol, a diluent such as butylacetate, and an acid catalyst, preferably orthonitrobenzoic acidinjected into a zone followed by injecting salt water.

U.S. Pat. No. 4,903,770 which issued Feb. 27, 1990, for "SandConsolidation Methods" describes a method employing an aerosol spraymade up with furfuryl alcohol, methanol, sulfuric acid and steam.

SUMMARY OF THE INVENTION

We have discovered that it is possible to treat a subterranean formationwhich exhibits a poor injectivity profile during secondary or tertiaryrecovery operations, in which the amount of steam entering differentintervals of the formation is significantly uneven, in order to reducethe variation in permeability of the different zones of the formation.By this treatment, the injectivity of fluid into the formation can bemade much more uniform and even, which results in the injected fluidaffecting a greater portion of the petroleum-containing formation, andthereby increasing the amount of oil that can be recovered from theformation. Our process can be used in conjunction with steam injection,whereas the materials used in many prior art well treating processes aredestroyed by contact with steam.

Our process involves injecting into the formation a fluid containing apolymerizable compound which can be polymerized by heat or acid tocross-link within the portion of the formation into which the compoundis injected, reducing the permeability of the very high permeabilityzones of the formation. The preferred polymerizable compounds are amonomer or oligomer of furfuryl alcohol. The furfuryl alcohol derivativecan be introduced as a substantially all liquid phase treating fluid,but in a particularly preferred embodiment, a two-phase aerosol treatingfluid comprising the polymerizable furfuryl alcohol monomer and steam orcompressed gas is formed and injected into the formation. When theaerosol is formed, a mixture comprising the furfuryl alcohol monomer,ethyl acetate as a diluent and as a reaction modifier, methylalcohol asa solvent and an acid to catalyzed the polymerization which may be analkyl benzene sulfonic acid such as toluene sulfonic acid or a mineralacid such as sulfuric acid. The treatment procedures should be appliedbefore significant portion of the steam is injected into the formation,and the application of this process greatly enhances the injectivityprofile of the subsequently injected steam.

DETAILED DESCRIPTION OF THE INVENTION INCLUDING THE PREFERREDEMBODIMENTS

Our invention is concerned with a method of treating subterraneanformations in order to alter the permeability distribution of thoseformations, which achieves a more uniform distribution of permeabilitywithin the formation. This treatment allows a subsequently injectedfluid for the purpose of stimulating oil recovery to pass more evenlythroughout the full vertical thickness of the formation, which resultsin a greater recovery effectiveness of the oil recovery process.Throughout this application, we will frequently refer to the injectionof steam, and indeed a preferred embodiment of our process involves aprocedure for treating a formation prior to steam injection or in someinstances in early stages of steam injection, and the process is uniquein that it can be used with steam stimulation without having the steamdestroy the permeability altering chemicals as is sometimes encounteredwith prior art methods. It should be understood, however, that thisprocedure may also be used with any oil recovery process in which afluid is injected into the formation to displace petroleum to the sameor a remotely located production well. Specifically, the process of ourinvention may be applied to a formation after which water injection isapplied, and the effect of treating with our process insures that waterdisplaces oil from a greater portion of the vertical thickness of theformation than would be possible without the application of our processprior to water injection. Application of this process in conjunctionwith surfactant flooding and polymer flooding, or combinations thereof,are also within the description contained herein.

I. THE STEAM AEROSOL EMBODIMENT

The especially preferred embodiment of our invention involvesapplication of a two phase aerosol fluid in which the polymerizablefurfuryl alcohol monomer is the dispersed liquid phase with steamconstituting the vapor phase of the aerosol mixture. The particularlyunique and beneficial effect of this embodiment resides in theeffectiveness in reducing the permeability of high permeability zones toa level more nearly equal to the permeability of the adjacent zoneswithout plugging these originally high permeability zones as many priorart processes do. Also, the quantity of chemical used in treating aformation using the steam aerosol embodiment of our process is much lessthan the quantity required in prior art processes employing a liquidphase treating fluid.

The polymerizable monomer which we have found to be especiallypreferable for use in the aerosol embodiment of our sand consolidationreaction is furfural alcohol. Any monomer which will polymerize uponexposure to heat and contact with an acid catalyst can be used in thisprocess; however, furfuryl alcohol (C₄ H₃ OCH₂ O) is the particularlypreferred polymerizable monomer. This material has the advantage ofbeing relatively inexpensive and having the characteristic ofautopolymerizing on exposure to acid catalyst, forming a thermal settingresin which cures to an insoluble mass that is highly resistant tochemical attack as well as to thermal degradation.

During the injecting step the mixture of steam, monomer, diluent andcatalyst enters the formation as an aerosol with steam vapor comprisingthe gaseous phase and dispersed drops of monomer and acid comprising thedispersed phase. The multiphase mixture is at or near steam temperature,which is ordinarily greater than the formation temperature. Drops ofmonomer and acid condense on the sand grains, which join together toform a liquid coating on the sand grains which reduces the void spacearound the sand grains, thereby reducing the permeability of the zone.Polymerization occurs quickly in this liquid film, the reaction ratebeing roughly first order with monomer concentration and pH. At 150° C.polymerization occurs in a matter of seconds, while the mixture ofmonomer and acid are stable and unreactive at surface conditions of 30°C. for several days.

The furfuryl alcohol utilized in our process is so reactive to acid thatit must be diluted with an appropriate solvent in order to permit it tobe dispersed in the steam and injected into the formation withoutpremature reaction. Presence of a diluent accomplishes relativelycomplete coating of the sand grains in the high permeability zones ofthe formation. Any inexpensive solvent for the furfuryl alcohol monomerwould accomplish this objective. Accordingly, our preferred diluent forthe furfuryl alcohol monomer is a low carbon alcohol, and our especiallypreferred solvent is methanol.

Many preferred embodiments of our invention employ a fluid to react withand remove water which is produced in the condensation reaction. Anacetate such as ethyl or butyl or other rapidly reacting anhydride isour preferred material for this purpose. Our preferred ester is ethylacetate.

It is necessary for this procedure that the acid catalyst utilized benon-volatile so that it remains in the liquid phase of the multiphasetreating fluid. This permits thorough mixing of the catalyst with thepolymerizable monomer which is essential in or order to ensure that thepolymerization reaction occurs uniformly throughout the entire mass offormation contacted by the polymerizable monomer. It is not necessary inour invention that once the fluid is placed in the formation, it be leftin a quiescent state for a long period of time sufficient to ensurecomplete reaction, as is required in many prior art methods. Thepolymerization reaction occurs very rapidly and is completed in arelatively brief period of time, so oil recovery fluid injection maybegin immediately.

Our methods are preferably accomplished using the following materialsand procedures. The steam aerosol embodiment of our invention isespecially successful when applied to formations containing heavy oilwhich ordinarily requires steam stimulation to achieve commercial oilrecovery rates. Such formations are typically relatively shallow, e.g.seldom deeper than 2,000 feet. If it is desired to apply the methods ofour invention to deeper formations, some modifications to the injectionprocedures may be required to avoid polymerization in the injectionline.

It is necessary that a source of steam be available at or near the well.The quality of steam is not critical to our process, and from 50 to 100percent steam may be used. The quality of steam must be known, however,since the ester must be incorporated in the consolidating fluid wheneverthe steam quality is below about 80 percent. When used, theconcentration of ester in the polymer fluid is from 5 to 30 andpreferably 20 to 30 percent by volume.

In applying this preferred embodiment, a treating fluid is provided onthe surface near the well. This fluid is liquid phase and comprises from10 to 50 and preferably from 20 to 30 percent by volume of apolymerizable monomer, usually furfuryl alcohol. Furfuryl is ourpreferred polymerizable monomer because it is inexpensive, readilyavailable, non-toxic, easily auto polymerized by acid, and forms astrong, durable polymer which withstands hostile conditions in theformation well including those associated with steam stimulation.

A diluent is used with furfuryl alcohol to reduce the reaction rate oncontact with acid. Directly mixing furfuryl alcohol with acid canproduce high reaction rates or even an explosion. Any polar organicdiluent may be used, but low molecular weight alcohol is the preferreddiluent and methanol is our especially preferred material. Non-polarsolvents must not be used since uncontrolled reaction rates includingexplosions result. The treating fluid should contain from 90 to 50 andpreferably from 80 to 70 percent by volume polar organic diluent. If anester is used in the fluid because of low steam quality, the volume ofsolvent is reduced accordingly so the total solvent amounts are asdescribed above.

The acid used to catalyze the polymerization of the monomer should benon-volatile strong acid. Sulfuric acid and trichloroacetic acid are thepreferred acids. The concentration of acid in the treating fluid is verycritical, since the acid concentration determines the reaction rate ofthe polymerization. Since the reactable monomer and acid are mixed withsteam on the surface, the temperature of the fluid will be known, butnot easily adjustable; therefore, the acid content of the treating fluidand the concentration of monomer are the primary means for controllingthe polymerization rate. It is desired that essentially little or noreaction occur in the injection string before the fluid enters theformation. Since the depth and temperature of the formation are wellknown and the fluid injection rate is controllable or known, it ispossible to adjust the acid content of the treating fluid sopolymerization occurs precisely when desired, which is shortly after thefluid enters the formation.

The following is a guideline for adjusting acid content of the treatingfluid for various formation temperatures in order to cause thepolymerization to occur in the desired time.

                  TABLE 1                                                         ______________________________________                                        Preferred Treating Fluid Acid                                                 Content For Various Temperatures                                                           Acid Content                                                     Temperature (°F.)                                                                   (Normality)      Time                                            ______________________________________                                         73          1                1.5   hr.                                                    .2               9     hr.                                                    .1               17    hr.                                                    .05              32    hr.                                       194          1                45    sec.                                                   .2               4     min.                                                   .1               8     min.                                                   .05              14    min.                                      300          1                6     sec.                                                   .2               30    sec.                                                   .1               60    sec.                                                   .05              2     min.                                      ______________________________________                                    

Ordinarily, this fluid is injected relatively fast when using a 1 to 3inch diameter line in the wellbore carrying treating fluid and steamwhere the steam generator delivers steam having quality values of from50 to 80 percent at a pressure of from 250 to 350 pounds per squareinch. Under these conditions the transit time in the injection stringwill be from 10 to 60 seconds.

In applying our methods, the consolidating fluid described above ismixed with steam on the surface, with the mixture passing through aninjection string and into the formation where permeability reduction isdesired. The fluid is mixed with steam in a volume ratio in the range ofone part treating fluid to from 0.2 to 1 and preferably 0.4 to 0.6 partsby volume steam.

The mixture of polymerizable resin-containing fluid and steam forms atwo-phase treating fluid, ideally an aerosol, and enters the formationin that form. The treating fluid droplets coalesce on the sand grains,forming a liquid coating on the said particles or other mineralsurfaces. Since the dispersed drops of liquid in the aerosol treatingfluid include the polymerizable monomer and the acid, the liquid filmformed on the formation surface comprises both monomer and acid. As thefilm forms, the polymerization of monomer begins due to presence of acidin the fluid and proceeds very rapidly. The vapor portion of steammaintains the void spaces between monomer-coated formation surfacesopen, which insures that the treated formation will have sufficientpermeability to allow passage of enhanced oil recovery fluid or oillater, after the coating has cured and steam injection has resumed.

The quantity of the treating fluid comprising the polymerizable monomer,diluent and catalyst injected into the formation varies depending on thethickness and porosity of the formation to which our process is to beapplied, as well as the diameter of the well and the desired thicknessof the treated zone in the formation. The thickness and porosity of theformation and the diameter of the well will always be known, and it isordinarily satisfactory if depth of the penetration of the treatment isin the range of from 6 to 12 inches from the well bore.

Since this process does not require completely filling the void space ofthe portion of the formation being treated with treating fluid, therequired volume of consolidating fluid is from 10 to 30 percent of thepore space of portion of the formation being treated. As an example, ifit is desired to treat a formation whose thickness is 18 feet andaverage porosity is 35% to reduce the permeability of the highpermeability zones in the formation from just outside the perforationsof the wellbore to a distance of 1.0 foot from the wellbore and the wellbeing treated is 10 inches in diameter, then the volume of fluidnecessary is calculated according to the example below. ##EQU1##monomer, diluent and acid. Since the consolidating fluid is mixed withsteam in the ratio of 4 to 1, the total volume of aerosol treating fluidis 271.5 gallons.

After the steam and treating fluid are injected, the well should be shutin and left to stand for a period of from 1 to 24 and preferably from 2to 9 hours to permit completion of the polymerization. Steam injectionmay then be resumed.

II. NONCONDENSABLE GAS AEROSOL FLUID EMBODIMENT

Another preferred embodiment for our process employs injecting anaerosol containing the furfuryl alcohol derivative in an aerosol form,similar to that described above; however, in this second embodiment, anoligomer of furfuryl alcohol is used, and a non-condensable gas such ascompressed air or nitrogen is utilized as the gas phase of themultiphase injection fluid.

The polymerizable oligomer which we have found to be especiallypreferable for use in our formation treating reaction is an oligomer offurfuryl alcohol. Any oligomer which will polymerize at formationtemperature with an acid catalyst can be used in this process; however,a fluid comprising an oligomer of furfuryl alcohol (C₄ H₃ OCH₂ O)_(n) isthe particularly preferred polymerizable oligomer. This material has theadvantage of being relatively inexpensive and having the characteristicof autopolymerizing on exposure to acid catalyst, forming a thermalsetting resin which cures to an insoluble mass that is highly resistantto chemical attack as well as to thermal degradation. A preferredcommercial product for this application is QO Chemicals QUACOOR 1300®Furan Resin. Although we found and reported above that a monomer offurfuryl alcohol is a preferred material when a similar process isapplied using steam to form the aerosol mixture, we have found that themonomer is not suitable in the present embodiment where the aerosol isformulated by spraying the acid catalyzable compound with thenon-condensable gas at essentially surface ambient temperatures. Thesteam aerosol system required 300° F. or greater temperatures to beginthe polymerization of the furfuryl alcohol monomer before it hits thesand face, as the less viscous monomer will not adhere to the sandgrains in the formations, and so a satisfactory treatment will not beachieved. Attempts were made to compensate for this by increasing theamount of catalyst used in the fluid containing furfuryl alcohol monomerand acid catalyst in the preparation of the steam monomer aerosol, butit was found that the furfuryl alcohol monomer was too reactive tocontrol at mixing and injection conditions.

The gas utilized in formulating the aerosol mixture can be any availablegas which is non-condensable at injection and formation conditions.Compressed air is the most likely candidate because it is inexpensiveand widely available. Nitrogen is also a preferred gas for this purpose.Although other gases might be used, air and nitrogen are the gases ofchoice because of availability and economy.

It is necessary that a source of non-condensable gas be available at ornear the well. Usually the most convenient way of forming the aerosoltreating fluid used in the process of our invention is with the use of aconventional air compressor, and spraying the liquid oligomer containingmaterial through an injection nipple to accomplish an even dispersal ofthe liquid resin in the gas stream. By proper choice of the injectionnozzle diameter, liquid pressure and the air pressure, it is possible toform a fairly fine spray containing relatively even size of droplets ofpolymerizable fluid and good droplet distribution in compressed air. Asa general rule, satisfactory results are achieved if the liquid isinjected through a 1/4 to 3/8 inch nozzle when the liquid injectionpressure is from 100 to 300 pounds per square inch, when injected into agas steam whose flow rate is from 2.2 to 3.3 SCF per hour.

We have found that the preferred aerosol can be formulated if a mixtureof the furfuryl alcohol oligomer, e.g. the QUACOOR 1300® Furan Resin ismixed with an ester. Although the ratio of the polymerizable resin toester may vary depending on the surface ambient temperature and theavailable gas pressure, we have found that the preferred results areobtained by using from 20 to 70 and preferably from 40 to 60 percent ofthe acid catalyzable furfuryl alcohol oligomer mixed with an ester,preferably butyl acetate. The predetermined concentration and choice ofacid catalyst is mixed with the resin ester mixture before the aerosolmixture is formulated, as described below.

It is essential for this procedure that the acid catalyst utilized beoil soluble so that it may be incorporated in the resin solventsolution. This permits thorough mixing of the catalyst which isessential in order to ensure that the polymerization reaction occursuniformly throughout the entire mass of treating chemical placed in theformation. The catalyst for use in our invention must also exhibittemperature sensitivity such that the catalytic polymerization does notoccur during the time that the fluid is prepared and mixed on thesurface of the earth and pumped into the formation. It is equallyimportant that once the fluid is placed in the formation and left in aquiescent state for a period of time sufficient to ensure temperatureequalization with the formation, that the polymerization reaction occurrapidly in order to permit completion of the procedure in a relativelybrief period of time, so injection of the oil recovery fluid into thewell can begin as soon as possible. Because of this dual requirement,the catalyst choice and concentration are both critical to the properfunction of our invention.

As stated above, the preferred catalyst for use in our process is onewhich is oil soluble and very slightly water soluble. While we havepreviously disclosed that the preferred organic acid catalyst isorthonitrobenzoic acid for processes being applied to relatively hightemperature (e.g., greater than 350° F.) formations, we have found thatat temperatures less than 350° F. and especially when the formationtemperature is below 280° F., orthonitrobenzoic acid is so weak and soinsoluble that the time required for polymerization to proceed at leastsufficiently far that no displacement of polymer from the sand grainoccurs, is in the range of several days to a week or more. This long settime causes several problems. The polymerizable compound, e.g. thefurfuryl alcohol, may be washed off the sand grains beforepolymerization proceeds far enough to render the polymer immobile, whichgreatly weakens the strength of the polymerized sand coating whichcauses the desired permeability reduction in the treated zone. Also, thetotal cost of a well treatment is greatly increased by the extendedperiod which the well is shut in, before injection of oil recovery fluidcan be resumed.

We have found that the desired set time of from 0.75 to 4.0 hours andpreferably from 1-2 hours can be realized for any particular formationtemperature in the range of 40° F. to 300° F. and especially from 60° to280° F. if the pK of the acid catalyst and the concentration of the acidcatalyst are carefully selected.

Once the acid has been selected, the acid concentration should bedetermined. The concentration of acid to yield the desired 0.75-4.0 hourset time is solely determined by the formation temperature. It isessential in applying our process to a formation that the temperature ofthe formation be known or measured. The following Table II gives therelationship between toluenesulfonic acid catalyst concentration andtemperature to produce set time within the preferred 1-2 hour range.

                  TABLE II                                                        ______________________________________                                        FORMATION       % TOLUENE-                                                    TEMPERATURE     SULFONIC                                                      °F.      ACID                                                          ______________________________________                                        Up to 80° F.                                                                           5.0-3.8                                                        80-120° F.                                                                            3.8-3.1                                                       120-140° F.                                                                            3.1-2.4                                                       140-200° F.                                                                            2.4-1.4                                                       200-230° F.                                                                            1.4-0.8                                                       230-260° F.                                                                            0.8-0.5                                                       260-300° F.                                                                            0.50                                                          ______________________________________                                    

Surprisingly, we have found that the above correlation holds for anymixture ratio of resin and the ester, e.g. butyl acetate, over thevolume ratio 20 to 80 to 80 to 20.

One preferred method for forming a particularly effective fluid for usein practicing the embodiment of our invention involves mixing anapproximately 50-50 mixture of the resin in its commercial form, whichis an emulsion, with butyl acetate, after which the toluenesulfonic acidcatalyst is dissolved in this mixture of resin and ester.

Since the melting point of toluenesulfonic acid is 223° F. it issometimes necessary to incorporate the acid in a suitable diluent,usually a low carbon alcohol such as methanol, to facilitate mixing itwith the resin emulsion. From 2 to 5 percent methanol is usuallyadequate for this purpose.

The quantity of the preflush used in the first step and the quality ofthe sand consolidating liquid comprising the resin, diluent and catalystused to form the aerosol which is injected into the formation in thesecond step of our process varies depending on the thickness andporosity of the formation to which the permeability modification processis to be applied, as well as the diameter of the well and the desiredthickness of the permeable barrier in the formation. The thickness andporosity of the formation and the diameter of the well will always beknown, and it is ordinarily satisfactory if depth of the penetration isin the range of from 1/4 to 1/2 foot from the well bore. A volume oftreating fluid equivalent to about 20% of the pore volume being treatedis required. As an example, if it is desired to treat a formation whosethickness is 18 feet and porosity is 35% adjust the permeability in theportion of the formation from just outside the perforations of thewellbore which extends into the formation for a distance of 1/2 foot,and the well being treated is 10 inches in diameter, then the volume ofpreflush and treating liquid necessary is calculated according to theexample below.

Radius of hole: ##EQU2## Radius of treated zone=0.5+0.417=0.917 ft.##EQU3##

42 cubic feet=11.4 gallons of the preflush and of the treating liquidcomprising resin, catalyst and ester.

In applying our methods, the treating liquid described above is mixedwith gas on the surface to form the aerosol treating fluid mixture whichpasses through an injection string and into the formation wherepermeability modification is desired. The fluid is mixed with gas in avolume ratio in the range of one part liquid to from 0.2 to 1 andpreferably 0.4 to 0.6 parts by volume gas.

The mixture of treating fluid and gas forms a two-phase mixture, ideallyan aerosol, and enters the formation in that form. The droplets oftreating liquid coalesce on the formation mineral surfaces, forming aliquid coating on the said surfaces. Since the dispersed drops of liquidin the aerosol treating fluid include the polymerizable oligomer and theacid, the liquid film formed on the mineral surfaces also comprises botholigomer and acid catalyst. As the film forms, the polymerization ofoligomer begins due to contact with acid and proceeds very rapidly. Thecarrier gas portion of the aerosol maintains the void spaces betweenoligomer-coated sand grains, which insures that the treating zone willhave sufficient permeability to allow oil recovery fluid and oil to flowthrough the treated zone after the coating has cured and oil productionhas been resumed.

Ordinarily, this aerosol treating fluid is injected relatively fast whenusing a 1 to 3 inch diameter line in the wellbore carrying treatingfluid and gas. Under these conditions the transit time in the injectionstring will be from 10 to 60 seconds.

III. LIQUID TREATING FLUID EMBODIMENT

Finally, there is a third preferred embodiment of our process, which isparticularly applicable to multi-well procedures in which an injectionfluid is injected into one or more wells to displace petroleum throughthe formation to one or more remotely located production wells. Thisembodiment is used preferably in connection with the injection of asubstantially all liquid phase displacement fluid for stimulatingpetroleum production such as water, or water-containing one or moresurface active agents to reduce the surface tension between the injectedfluid and the displaced fluid, or a polymer to increase the viscosity ofthe injected fluid in order to improve the mobility ratio between theinjected fluid and displaced fluid, or a combination of several of thesefluids. All of these displacement procedures share the commonrequirement that an injected fluid pass somewhat evenly and uniformlythrough the formation to displace petroleum toward a remotely locatedwell, and adverse permeability distribution will reduce theeffectiveness of any of these oil recovery processes. Accordingly, inthis embodiment of our invention a procedure is applied to a formationprior to the injection of water or chemicalized fluids for oil recoveryin order to alleviate injectivity distribution problems caused by poorpermeability uniformity in a formation.

The resin which we have found to be especially preferable for use inthis embodiment of our permeability modification process is a furfurylalcohol oligomer. Any resin which will polymerize upon exposure to heatand contact with an acid catalyst can be used in this process; however,furfuryl alcohol oligomer (C₄ H₃ OCHO)_(n) is the particularly preferredpolymerizable resin. This resin has the advantage of being relativelyinexpensive and having the characteristic of autopolymerizing onexposure to acid catalyst, forming a thermal-setting resin which curesto an insoluble mass that is highly resistant to chemical attack as wellas to thermal degradation. The particularly preferred commercial form inwhich this resin is available is Quacorr 1300® marketed by QO Chemicals.This resin is ordinarily obtained commercially in a form containing 90to 95 percent furfuryl alcohol oligomer.

The furfuryl alcohol oligomer emulsion utilized in our process is soviscous that it must be diluted with an appropriate solvent in order topermit it to be pumped into the formation, and to accomplish relativelycomplete coating of sand grains or formation surfaces in the highpermeability zones of the formation. Any solvent for the furfurylalcohol oligomer would accomplish this objective. It is possible,however, to accomplish this and another more important objective byusing as the diluent a hydrolyzable ester. The polymerization of thefurfuryl alcohol oligomer produces water and the water produced bypolymerization suppresses the polymerization reaction. If water producedduring polymerization of furfuryl alcohol oligomer can be removed, it ispossible to force the polymerization reaction to proceed further towardcompletion and thereby produce longer polymer chains than would resultif water were left in the polymer reaction mass. A hydrolyzable esterwill remove water as it is produced, leading to the formation of longerchain polymers which result in a stronger, more durable polymer matrixwhich coats formation sand grains or matrix surfaces to reduce thepermeability of high permeability zones in the formation. Accordingly,our preferred diluent for the furfuryl alcohol oligomer is ahydrolyzable ester such as ethyl or butyl acetate, and our especiallypreferred species is butyl acetate.

It is essential for this procedure that the acid catalyst utilized beoil soluble so that it may be incorporated in the resin solventsolution. This permits thorough mixing of the catalyst which isessential in or order to ensure that the polymerization reaction occursuniformly throughout the entire mass of treating chemical placed in theformation. Prior art methods which utilize a catalyst injected in anon-miscible fluid either before or after injection of the fluidcontaining the polymerizable resin, or present in a non-miscible phaseof the polymer fluid, do not accomplish uniform reactions such as arepossible by use of the present soluble catalyst. The catalyst for use inour invention must also be one which exhibits temperature sensitivitysuch that the catalytic polymerization does not occur during the timethat the fluid is prepared and mixed on the surface of the earth orpumped into the formation. It is equally important that once the fluidis placed in the formation and left in a quiescent state for a period oftime sufficient to ensure temperature equalization with the formation,that the polymerization reaction occur rapidly in order to permitcompletion of the procedure in an relatively brief period of time, sofluid injection can be initiated as soon as possible. Because of thisdual requirement, both the catalyst choice and concentration are verycritical to the proper function of our invention.

While orthonitrobenzoic acid is useful for processes being applied torelatively high temperature (e.g., greater than 350° F.) formations, wehave found that at temperatures less than 350° F. and especially whenthe formation temperature is below 300° F., orthonitrobenzoic acid is soweak and so insoluble that the time required for polymerization toproceed at least sufficiently far that no displacement of polymer fromthe formation surface occurs, is in the range of several days to a weekor more. This long set time causes several problems. The polymerizablecompound, e.g. the furfuryl alcohol, may be washed off the formationsurface before polymerization proceeds far enough to render the polymerimmobile, which greatly weakens the quality of the formationpermeability treatment. Also, the total cost of a well treatment isgreatly increased by the extended period which the well is shut in,which delays initiating fluid injection.

We have found that the desired set time of from 0.75 to 4.0 andpreferably from 1-2 hours can be realized for any particular formationtemperature in the range of 60° F. to 350° F. and especially from 100°to 350° F. if the pK of the acid catalyst and the concentration of theacid catalyst are carefully selected.

The pK of an organic acid is defined as the negative of the ionizationconstant of the acid and is essentially an inverse scale measure of thestrength of the acid, e.g. strong acids have lower pK values. The acidcatalyst for this process must be an organic acid which is oil solubleand which has a pK in the range of 0.5 to 2.0 and preferably from 0.7 to1.3. The especially preferred acid for this embodiment of our process istoluenesulfonic acid, usually paratoluenesulfonic acid, although mixedisomers may also be used. The following organic acids may also be used:chloroacetic acid, dichloroacetic acid, trichloroacetic acid andarylsulfonates. Mixtures of toluenesulfonic acid with the above may beused. For convenience, a mixture comprising 95% toluenesulfonic acidwith 5% xylenesulfonic acid has been used in the field because themixture is liquid at field conditions and therefore easier to mix withthe other fluids in preparing the treating fluid. This is a commercialproduct available under the trade name WITCAT TX ACID®. Other mixturesmay also be used, to ensure that the melting point is below ambienttemperature.

Once the acid has been selected, the acid concentration should bedetermined. The concentration of acid to yield the desired 0.75-4.0 hourset time is solely determined by the formation temperature. It isessential in applying our process to a formation that the temperature ofthe formation be known or measured. The following table gives therelationship between toluenesulfonic acid catalyst and temperature toproduce set time within the preferred 1-2 hour range.

                  TABLE III                                                       ______________________________________                                        FORMATION       % TOLUENE-                                                    TEMPERATURE     SULFONIC                                                      °F.      ACID                                                          ______________________________________                                        Up to 80° F.                                                                           5.0-3.8                                                        80-120° F.                                                                            3.8-3.1                                                       120-140° F.                                                                            3.1-2.4                                                       140-200° F.                                                                            2.4-1.4                                                       200-230° F.                                                                            1.4-0.8                                                       230-260° F.                                                                            0.8-0.5                                                       260-300° F.                                                                            0.50-0.3                                                      ______________________________________                                    

Surprisingly, we have found that the above correlation holds for anymixture ratio of resin in the ester, e.g. butyl acetate, over the volumeratio 90 to 10 to 40 to 60.

One preferred method for forming a particularly effective fluid for usein practicing the process of our invention involves mixing anapproximately 50-50 mixture of the resin in its commercial form, whichis usually an emulsion, with butyl acetate, after which thetoluenesulfonic acid catalyst is dissolved in this mixture of resin andester.

Since the melting point of toluenesulfonic acid is 223° F., it issometimes necessary to incorporate the acid in a suitable diluent,usually a low carbon alcohol such as methanol, to facilitate mixing itwith the resin emulsion. From 2 to 5 percent methanol is usuallyadequate for this purpose.

The quantity of the fluid comprising the resin, diluent and catalystinjected into the formation varies depending on the thickness andporosity of the formation to which the sand consolidation process is tobe applied, as well as the diameter of the well and the desiredthickness of the permeable barrier in the formation as is described inthe last embodiment described above.

The polymerizable resin used to prepare the treating fluid is normallyavailable commercially as a mixture containing about 5 percent water.The strength of the coating formed on the mineral surfaces in thetreated zones of the formation will be increased if at least a portionof this water is removed before the resin polymerizes. We have foundthat the desired strength is best accomplished by injecting brine orwater containing an inorganic salt, preferably sodium chloride, into thestring to displace the residual amount of resin fluid from the injectionstring, and also to pass through the portion of the of the formationoccupied by the resin fluid. Injection of the brine developspermeability within the treated portion of the formation which ensuresthat after the resin has polymerized, the resultant zone will besufficiently permeable to the flow of fluids to allow passage ofinjected fluid through the zone. The salinity of water utilized in thisprocedure is quite important. The surface of the resin coated sandgrains should be de-watered in order to aid in the polymerizationreaction and also in order to produce a denser stronger matrix coatingthe formation mineral surface. Fresh water or water containing up to 70percent salt does not accomplish the drying action necessary to producethe desired strength in the polymerized coating. The desired resultswill only be achieved if the second fluid injected into the formation isat least 70% saturated with respect to the inorganic salt and preferably80% saturated. Our particular preferred embodiment uses essentiallysaturated brine, specifically water saturated with sodium chloride atthe conditions of injection. By using at least 70% saturated brine, thedesired development of permeability is achieved without displacing anyof the resin from the mineral surfaces and dehydration of the resinnecessary for the polymerization reaction to occur in the time and tothe extent desired for optimum polymerization is also realized.

As a practical matter, the brine utilized will probably be watercontaining mainly sodium chloride because of the cost and availabilityof sodium chloride in the field. This is a particularly preferred brinefor our purpose. We have discovered that potassium chloride does notwork well in this application, and so the fluid injected into theformation after the polymerization fluid has been injected should notcontain appreciable quantities of potassium chloride. The quantity ofbrine injected into the formation should be sufficient to displace allof the residual resin fluid from the injection string, and alsosufficient to pass through the resin treated portion of the formation.It is generally sufficient if about the same volume of brine as thepolymerization fluid is utilized, and the rate at which it is injectedis not particularly critical for our purposes.

After the above steps of injecting the polymerization fluid and thesodium chloride solution or brine are completed, the well should be shutin and left to stand for a period of from 1 to 4 and preferably from 1to 2 hours. The time required for the polymerization reaction to proceedto completion is predetermined by the procedure discussed above andshould be in the range of 1-2 hours.

In application of either the sand consolidation or water shut offembodiment of our invention, leaving the well shut in for more than 2hours will have no adverse effect on the process, and indeed thestrength of the polymerized resin may increase in this additionalperiod. The set time as described herein only defines the time in whichthe resin will proceed to a minimum level to prevent removing thepolymer from the formation mineral surfaces.

FIELD EXPERIMENT

An opportunity arose to test our process in a field being subjected tosteam stimulation. In this particular case, a plurality of wells werecompleted in a relatively shallow formation which is about 50 feet thickand contains viscous petroleum. Each well is used as both an injectionwell and a production well. A sand consolidation process has beendeveloped for treating these wells which was applied at the end of thesteam injection phase, and before production of petroleum began, inorder to reduce the production of the sand from the formation into thewell in the subsequent oil production cycle. The treatment, of course,had no effect on the steam injection distribution, since it was appliedat the end of the steam phase and before production began, which waswhen the concern for sand control effectiveness arises. Treatment of thewell at the beginning of the steam injection phase would not effectivelyreduce sand production after the completion of the steam injection phaseand production began, because the continued injection of steam over aperiod of 1 to 2 weeks as was the practice in this particular fieldwould eventually destroy the polymerized coating before production everbegan, so sand control would not be accomplished.

A steam injection profile was run on the interval being stimulated. Inone particular case, it was found that in a fifty foot interval offormation, approximately 95% of the total amount of steam being injectedinto the formation was entering the top 25 feet or 50 percent of thethickness of the formation, while the bottom 50 percent or 25 feet ofthe formation was receiving only five percent of the steam. This meantthat the bottom of the petroleum containing interval was receiving verylittle steam and therefore would not respond to the steam stimulationproduction and little oil recovery would be obtained from that bottomportion of the interval.

It was decided to apply the process of our invention by forming anaerosol comprising dispersed liquid drops of furfuryl alcohol monomer insteam and injecting this aerosol treating fluid into the formation forthe purpose of improving the steam injectivity profile.

A preflush of 50 liters of ethyl acetate was injected into the steam.Next, 100 liters of treatment fluid comprised of 40 liters furfurylalcohol, 30 liters of ethyl acetate, 30 liters of methyl alcohol, and1/2 liter of sulfuric acid was mixed and then injected into the steam,at a rate of 21 liters per minute. The chemical injection unit was thendisconnected and the steam injection was continued for one week.

After the above described treatment, the injection profile of theinterval was again measured and it indicated that 45 percent of thesteam was now entering the upper fifty percent or twenty-five feet ofthe interval, whereas 55 percent of the steam was entering the lowerfifty percent or 25 feet of the interval. This represents a dramaticimprovement, since the portion which was originally receiving almostnone of the steam, was now receiving more than half of the steam. As aresult of this treatment, substantially more of the oil containingformation was contacted by steam, and so significantly improved oilrecovery from the zone previously unstimulated by steam was achieved. Itis especially noteworthy that this very significant improvement wasachieved in only one treatment, and that the amount of resin used wasonly about 1/2 gallon per foot of formation treated.

While our process has been described above in terms of a number ofillustrative embodiments, including what we believe to be the bestembodiment known to us at the present time, it is clearly not so limitedsince many variations thereof will be apparent to persons skilled in theart. It is our intention that our invention be limited only by thelimitations contained in the claims appended immediately hereinafterbelow.

We claim:
 1. A method for treating a subterranean petroleum-containingformation penetrated by at least one well in fluid communication withthe formation, said formation comprising at least two layered intervalshaving differing permeabilities to fluid injection, including a firstinterval of relatively high permeability and a second interval ofrelatively lower permeability, in order to improve the injectivityprofile of the formation to subsequently-injected oil recovery fluid,comprising:(a) providing an aerosol treating fluid comprising steam, apolymerizable compound comprising a monomer or oligomer or furfurylalcohol, a diluent for the compound, and an acid catalyst capable ofcausing polymerization of the polymerizable compound at formationtemperatures, said acid being selected from the group consisting ofsulfuric acid, toluene sulfonic acid, phosphoric acid, trichloroaceticacid, nitric acid and mixtures thereof; (b) injecting said treatingfluid into the formation to pass into the more permeable interval of thepetroleum formation and to deposit on the mineral surfaces of theformations; and (c) allowing the injected treating fluid to remain inthe formation for a period of time sufficient to accomplish at leastpartial polymerization of the polymerizable compound, thereby reducingthe permeability of the more permeable layer of the formation, so anincreased portion of the subsequently injected oil recovery fluid entersthe second interval.
 2. A method as recited in claim 1 wherein thepolymerizable compound is a monomer of furfuryl alcohol.
 3. A method asrecited in claim 1 wherein the polymerizable compound is an oligomer offurfuryl alcohol.
 4. A method as recited in claim 1 wherein the diluentis a low molecular weight alcohol.
 5. A method as recited in claim 4wherein the diluent is methanol.
 6. A method as recited in claim 1wherein the diluent is an ester.
 7. A method as recited in claim 6wherein the ester is ethyl acetate.
 8. A method as recited in claim 1wherein the volume of treating fluid injected into the formation issufficient to coat the mineral surfaces in the more permeable intervalfor a distance of from 1/2 to 1 foot from the wellbore.
 9. A method asrecited in claim 1 wherein the polymerizable compound is a monomer offurfuryl alcohol.
 10. A method as recited in claim 9 wherein theconcentration of the furfuryl alcohol monomer is from 10 to 50 percentby volume based on the total volume of the treating fluid.
 11. A methodas recited in claim 9 wherein the concentration of the furfuryl alcoholmonomer is from 20 to 30 percent by volume based on the total volume ofthe treating fluid.
 12. A method as recited in claim 1 wherein thediluent is a low molecular weight alcohol.
 13. A method as recited inclaim 12 wherein the diluent is methanol.
 14. A method as recited inclaim 12 wherein the concentration of alcohol in the treating fluid isfrom 90 to 50 percent by volume.
 15. A method as recited in claim 12wherein the concentration of alcohol in the treating fluid is from 90 to70 percent by volume.
 16. A method as recited in claim 1 wherein thecatalyst is sulfuric acid.
 17. A method as recited in claim 1 whereinthe concentration of acid catalyst in the treating fluid is from 0.1 to1.0 normal.
 18. A method as recited in claim 1 wherein the concentrationof acid catalyst in the treating fluid is from 0.25 to 0.5 normal.
 19. Amethod as recited in claim 1 wherein the volume ratio of treating fluidto steam is from 0.2 to
 1. 20. A method as recited in claim 1 whereinthe acid content of the treating fluid is adjusted to causepolymerization to occur after a time slightly greater than the timerequired for the steam and treating fluid to be injected into theformation.
 21. A method as recited in claim 1 wherein the fluids areleft in the formation for a period of at least 6 hours.
 22. A method asrecited in claim 1 wherein the treating fluid also contains an ester.23. A method as recited in claim 22 wherein the ester is butyl acetate.24. A method as recited in claim 22 wherein the concentration of esteris from 20 to 30 volume percent.
 25. A method as recited in claim 22wherein the steam quality is below 80 percent and the esterconcentration is from 20 to 30 percent.